1. Technical Field of the Invention
This Invention relates to a novel reversible thickener, i.e., a fluid whose viscosity can be carefully modulatedxe2x80x94from very low viscosity to sufficient viscosity to act as a barrier to further flow; particularly preferred embodiments are directed to fluids and methods for stimulating hydrocarbon-bearing formationsxe2x80x94i.e., to increase the production of oil/gas from the formation. In particular, the Present Invention is directed to a family of fluids (and methods incorporating those fluids) intended to be pumped through a wellbore and into the hydrocarbon-bearing formation.
2. Introduction to the Technology
For ease of understanding, the novel fluid systems of the Present Invention will be described with respect to their preferred commercial applications. Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a xe2x80x9creservoirxe2x80x9d) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the oil to reach the surface. In order for oil to be xe2x80x9cproduced,xe2x80x9d that is, travel from the formation to the wellbore (and ultimately to the surface) there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rockxe2x80x94e.g., sandstone, carbonatesxe2x80x94which has pores of sufficient size and number to allow a conduit for the oil to move through the formation.
One of the most common reasons for a decline in oil production is xe2x80x9cdamagexe2x80x9d to the formation that plugs the rock pores and therefore impedes the flow of oil. Sources of formation damage include: spent drilling fluid, fines migration, paraffin, mineral precipitation (scale). This damage generally arises from another fluid deliberately injected into the wellbore, for instance, drilling fluid. Even after drilling, some drilling fluid remains in the region of the formation near the wellbore, which may dehydrate and form a coating on the wellbore. The natural effect of this coating is to decrease permeability to oil moving from the formation in the direction of the wellbore.
Another reason for lower-than-expected production is that the formation is naturally xe2x80x9ctight,xe2x80x9d (low permeability formations) that is, the pores are sufficiently small that the oil migrates toward the wellbore only very slowly. The common denominator in both cases (damage and naturally tight reservoirs) is low permeability. Techniques performed by hydrocarbon producers to increase the net permeability of the reservoir are referred to as xe2x80x9cstimulation techniques.xe2x80x9d Essentially, one can perform a stimulation technique by: (1) injecting chemicals into the wellbore to react with and dissolve the damage (e.g., wellbore coating); (2) injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (thus rather than removing the damage, redirecting the migrating oil around the damage); or (3) injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel through which hydrocarbon can more readily move from the formation and into the wellbore. The Present Invention is directed primarily to the latter two of these three processes.
Thus, the Present Invention relates to methods to enhance the productivity of hydrocarbon wells (e.g., oil wells) by removing (by dissolution) near-wellbore formation damage or by creating alternate flowpaths by dissolving small portions of the formationxe2x80x94by techniques known as xe2x80x9cmatrix acidizing,xe2x80x9d and xe2x80x9cacid fracturing.xe2x80x9d Generally speaking, acids, or acid-based fluids, are useful in this regard due to their ability to dissolve both formation minerals (e.g., calcium carbonate) and contaminants (e.g., drilling fluid coating the wellbore or that has penetrated the formation) which were introduced into the wellbore/formation during drilling or remedial operations.
At present, matrix acidizing treatments are plagued primarily by three very serious limitations: (1) radial penetration; (2) axial distribution; and (3) corrosion of the pumping and well bore tubing. The Present Invention is directed primarily to the first two, and to the largest extent, the second.
The first problem, radial penetration, is caused by the fact that as soon as the acid is introduced into the formation (or wellbore) it reacts very quickly with the wellbore coating, or formation matrix (e.g., sandstone or carbonate). In the case of treatments within the formation (rather than wellbore treatments) the formation near the wellbore that first contacts the acid is adequately treated, though portions of the formation more distal to the wellbore (as one moves radially, outward from the wellbore) remain untouched by the acidxe2x80x94since all of the acid reacts before it can get there. For instance, sandstone formations are often treated with a mixture of hydrofluoric and hydrochloric acids at very low injections rates (to avoid fracturing the formation). This acid mixture is often selected because it will dissolve clays (found in drilling mud) as well as the primary constituents of naturally occurring sandstones (e.g., silica, feldspar, and calcareous material). In fact, the dissolution is so rapid that the injected acid is essentially spent by the time it reaches a few inches beyond the wellbore. Thus, one can calculate that over 100 gallons of acid per foot is required to fill a region five feet from the wellbore (assuming 20% porosity and 6-inch wellbore diameter). Yet, the high rate of acid spending would confine the dissolution of minerals to at most, a distance of one foot away from the wellbore, if a conventional fluid (HCl, or a mixture of HCl and HF) were used. Similarly, in carbonate systems, the preferred acid is hydrochloric acid, whiSch again, reacts so quickly with the limestone and dolomite rock, that acid penetration is limited to from a few inches to a few feet. In fact, due to such limited penetration, it is believed matrix treatments are limited to bypassing near-wellbore flow restrictionsxe2x80x94i.e., they do not provide significant stimulation beyond what is achieved through (near-wellbore) damage removal. Yet damage at any point along the hydrocarbon flowpath can impede flow (hence production). Id. Therefore, because of the prodigious fluid volumes required, these treatments are severely limited by their cost.
A second major problem that severely limits the effectiveness of matrix acidizing technology, is axial distribution. This problem relates to the proper placement of the acid-containing fluidxe2x80x94i.e., ensuring that it is delivered to the desired zone (i.e., the zone that needs stimulation) rather than another zone. (Hence this problem is not related per se to the effectiveness of the acid-containing fluid.) More particularly, when an oil-containing formation (which is quite often, though not always, comprised of calcium carbonate) is injected with acid (e.g., hydrochloric acid, or HCl) the acid begins to dissolve the carbonate; as one continues to pump the acid into the formation, a dominant channel through the matrix is inevitably created. And as one continues to pump acid into the formation, the acid will naturally flow along that newly created channelxe2x80x94i.e., the path of least resistancexe2x80x94and therefore leaving the rest of the formation untreated. This of course is undesirable. It is exacerbated by intrinsic heterogeneity with respect to permeability (common in many formations)xe2x80x94this occurs to the greatest extent in natural fractures in the formation and due to high permeability streaks. Again, these regions of heterogeneity in essence attract large amounts of the injected acid, hence keeping the acid from reaching other parts of the formation along the wellborexe2x80x94where it is actually desired most. Thus, in many cases, a substantial fraction of the productive, oil-bearing intervals within the zone to be treated are not contacted by acid sufficient to penetrate deep enough (laterally in the case of a vertical wellbore) into the formation matrix to effectively increase its permeability and therefore its capacity for delivering oil to the wellbore.
Again, the problem of proper placement is a particularly vexing one since the injected fluid will preferentially migrate to higher permeability zones (the path of least resistance) rather than to the lower permeability zonesxe2x80x94yet it is those latter zones which require the acid treatment (i.e., because they are low permeability zones, the flow of oil through them is diminished). In response to this problem, numerous, disparate techniques have evolved to achieve more controlled placement of the fluidxe2x80x94i.e., to divert the acid away from naturally high permeability zones and zones already treated, and towards the regions of interest. These shall be described below.
The Prior Art
Though the Present Invention is directed primarily to matrix acidizing, it is entirely applicable to a closely related stimulation technique, acid fracturing, which is very similar, but involves pumping the acid at or above pressures sufficient to fracture the formation (minimum in situ rock stress). For convenience sake, the focus here shall be directed to matrix acidizing.
The techniques to control acid placement (i.e., to ensure effective zone coverage) can be roughly divided into either mechanical or chemical techniques. Mechanical techniques include ball sealers (balls dropped into the wellbore and that plug the perforations in the well casing, thus sealing the perforation against fluid entry); packers and bridge plugs, particularly including straddle packers (mechanical devices that plug a portion of the wellbore and thereby inhibit fluid entry into the perforations around that portion of the wellbore); coiled tubing (flexible tubing deployed by a mechanized reel, through which the acid can be delivered with more precise locations within the wellbore); and bullheading (attempting to achieve diversion by pumping the acid at the highest possible pressurexe2x80x94just below the pressure that would actually fracture the formation).
Chemical techniques can be further divided into ones that chemically modify the wellbore adjacent to portions of the formation for which acid diversion is desired, and ones that modify the acid-containing fluid itself. The first type involve materials that form a reduced-permeability cake on the wellbore face which upon contact with the acid, will divert it to higher permeability regions. The second type includes foaming agents, emulsifying agents; and gelling agents.
The state-of-the-art mechanical techniques possess (individually and collectively) numerous shortcomings (See, e.g., G. R. Coulter and A. R. Jennings, Jr., A Contemporary Approach to Matrix Acidizing, 14(2) SPE Prod. and Facilities 150, 152 (1999)) Ball sealers, aside from the fact that they only work well in cemented/perforated casing, require sufficient rate/perforationxe2x80x94at least 0.25 barrels per minute per perforationxe2x80x94to secure the balls to the perforation. Hence, ball sealers can easily become detached from the perforations and plug pumps and chokes (although some state-of-the-art ball sealers are water soluble).
Packers, particularly straddle packers, require a rig (very expensive) or coiled tubing (moderately expensive) to move and place in the wellbore. And like ball sealers, any intrinsic feature in the formation that can conduct fluids out of the target zone (e.g., a fracture) will render these mechanical techniques ineffective.
Coiled tubing (thin-diameter steel or composite tubing wound around a mechanized reel and injected into a wellbore) is another commercial solution to the acid placement problem. By consensus, coiled tubing is at best an incomplete solution since it requires either another diversion method (e.g., chemical or mechanical) or the operator can try to place the acid by simultaneously pumping two fluids and balancing the pressures downhole.
Still other operators attempt to divert acid away from high permeability zones and towards the low permeability zones by a technique known as xe2x80x9cbullheading.xe2x80x9d In this technique, acid is pumped at very high pressuresxe2x80x94as high as possible without actually fracturing the formation.
Again, aside from the mechanical techniques just discussed, numerous chemical techniques have evolved, and as we have said, they can be conveniently divided into two categories, depending upon whether they are directed to modifying the wellbore face or to modifying the acid itself. First we shall discuss chemical diversion systems directed to modifying the acid.
The primary fluids used in acid treatments are mineral acids such as hydrochloric acid, which was disclosed as the fluid of choice in a patent issued over 100 years ago (U.S. Pat. No. 556,669, Increasing the Flow of Oil Wells, issued to Frasch, H.). At present, hydrochloric acid is still the preferred acid treatment in carbonate formations. For sandstone formations, the preferred fluid is a hydrochloric/hydrofluoric acid mixture.
Again, the major drawback of these acids are that they react too quickly and hence penetrate (as unspent acid) into the formation poorly. Second, they are highly corrosive to wellbore tubular components. Organic acids are a partial response to the limitations of mineral acids. The principal benefit of the organic acids are lower corrosivity and lower reaction rate (which allows greater radial penetration of unspent acid). The organic acids used in conventional treatments are formic acid and acetic acid. Both of these acids have numerous shortcomings. First, they are far more expensive than mineral acids. Second, while they have a lower reaction rate, they also have a much lower reactivityxe2x80x94in fact, they do not react to exhaustion of the starting materials, but rather remain in equilibrium with the formation rock. Hence one mole of HCl yields one mole of available acid (i.e., H+), but one mole of acetic acid yields substantially less than one mole of available acid.
Emulsified acid systems and foamed systems are other commercially available responses to the diversion problem, but they are fraught with operational complexity which severely limits their usexe2x80x94e.g., flow rates of two fluids, and bottom hole pressure must be meticulously monitored during treatment.
That leaves gelling agentsxe2x80x94the class of diverters to which the Present Invention most closely belongs. Though they are commercially available, gelling agents are quite often undesirable in matrix acidizing since the increased viscosity makes the fluid more difficult to pump (i.e., the same resistance to flow that confers the pressure build-up in the formation and results in the desired diversion, actually makes these fluids difficult to pump). Some commercially available systems are cross-linked systemsxe2x80x94i.e., they are linear polymers when pumped but a chemical agent pumped along with the polymer causes the polymers to aggregate or cross-link once in the wellbore, which results in gelling. Unfortunately, these systems leave a residue in the formation, which can damage the formation, resulting in diminished hydrocarbon production. Severe well plugging, particularly in low pressure wells, caused by these systems has been well documented. In addition, the success of these systems is naturally dependent upon a very sensitive chemical reactionxe2x80x94the cross-linkingxe2x80x94which is very difficult to optimize so that it is delayed during pumping but maximized once in the wellbore. This reaction is easily perturbed by formation chemistry, contaminants in the pumping equipment, and so forth. And again, once these systems are in place, they are difficult to removexe2x80x94to do so requires that they be somehow un-cross linked.
Hence, superior gelling systems have evolved which are not based on cross-linking chemistry, but which rely upon viscoelastic surfactants which are easy to pump (very low friction pressure) and yet which form a gel, or viscosify, once in the wellbore (due to their low resistance to shear from pumping). One system of this type is disclosed in U.S. Pat. No. 4,695,389 (see also, U.S. Pat. No. 4,324,669, and British Patent No. 2,012,830, both cited there)xe2x80x94which has a common assignee as the present application. In particular, the ""389 patent discloses a viscoelastic surfactant-based gelling agent intended for use in acid fracturing. The particularly preferred embodiment is a fluid comprised of N,N-bis(2-hydroxyethyl) fatty amine acetic acid salt (the gelling agent), an alkali metal acetate salt, acetic acid (the acidxe2x80x94which actually removes the damage from the formation), and water.
Another viscoelastic surfactant-based gelling system, also proprietary to Schlumberger, is known as OilSEEKER(trademark), and is disclosed in F. F. Chang, et al., Case Study of a Novel Acid-Diversion Technique in Carbonate Reservoirs, SPE 56529, p. 217 (1999). This system differs from the Present Invention in that it is not a self-diverting systemxe2x80x94i.e., the OilSEEKER treatment is performed in two steps: (1) injecting the diverter, followed by; (2) injecting the acid. The treatments based on the fluids of the Present Invention are based on a single stepxe2x80x94hence it is chemically very differentxe2x80x94because the diverter is contained within the acid-containing fluid.
The second group of chemical diversion techniques are directed to diverting acid flow by modifying the wellbore face (the point of entry for the acid into the reservoir). Most often, these techniques rely on the use of particulate material, either oil-soluble or water-soluble particulatesxe2x80x94which are directed at the high permeability zones to plug them and therefore divert acid flow to the low permeability zones. Obviously, these techniques are very sensitive to any feature in the reservoir that will conduct these particulates out of the target zone, for instance a natural fracture. Moreover, the purpose of the particulate material is to deposit a very low permeability filtercake on the wellbore face. This cake can often be difficult to clean upxe2x80x94e.g., oil-soluble diverters are not well suited for water injection wells or in high water cut wells. Moreover, the diverter particles must be carefully matched with the formation to prevent internal filtercake depositionxe2x80x94otherwise they will cause permanent pluggingxe2x80x94yet still create a low enough permeability to cause adequate pressure build-up which results in diversion.
Still, a need exists for a diversion system having even more finely modulatable viscosityxe2x80x94i.e., a fluid that exhibits very high resistance to shear and low viscosity during pumping, that gels quickly once it reaches the target, that forms a gel of sufficient strength to allow diversion to occur, and that is immediately and nearly completely xe2x80x9cbrokenxe2x80x9d or returned to the un-gelled state as soon as the treatment has ceased and the well is put back on production.
In this section, we shall discuss the invention itself and the primary commercial setting for the novel chemistry disclosed and claimed here.
Frequently a hydrocarbon-bearing reservoir will produce far less oil (or gas) than expectedxe2x80x94either due intrinsic features of the reservoir or because of chemical damage to the reservoir caused during drilling the wellbore; in some of those instances, it is desirable to xe2x80x9cstimulatexe2x80x9d the oil-bearing zone to increase production (or the flow of oil from the reservoir to the surface). Generally speaking, there are two techniques to do that: fracturing and matrix acidizing. The Present Invention is directed primarily, though not exclusively, to the latter technique.
We have discovered a novel gelling system that exhibits tightly reversible behaviorxe2x80x94that is, the fluid can be made to gel, then deliberately be broken (un-gelled) as needed. Broadly speaking, these systems are not new in the art, but what is in part new is the particular systemxe2x80x94i.e., the gelling composition combined with the chemical triggers (whether provided from the ambient matrix or deliberately added). In certain particularly preferred embodiments (related to matrix acidizing) the chemical triggers are supplied by the geologic matrix (i.e., they are not added deliberately as a separate step), further contributing to the novelty of the Present Invention. Aside from this, the commercial applications of the Present Invention are essentially unlimited. Broadly speaking, the Present Invention is directed to a reversible thickener which is highly stable with respect to certain solutes (in preferred embodiments, strong acid is used), which is readily pump-able (i.e., is shear resistant), whose viscosity can then be selectively and substantially increased, even to the extent that it can form a barrier thereby diverting the solute from its prior flowpath, and whose viscosity can be readily broken by a simple chemical trigger.
For convenience sake, we shall refer to preferred or particularly preferred embodiments of the. fluid of the Present Invention as xe2x80x9cSDAxe2x80x9d (self-diverting acid). Particularly preferred embodiment of the fluid of the Present Invention are comprised of: (1) a gelling agent (or primary surfactant); (2) a co-surfactant; (3) an acid (e.g., dilute HCl, HF, acetic acid, formic acid); and (4) water. Particularly preferred gelling agents are shown below: 
where m=10-22, n=1-5, p=1-3, and x=8-10.
According to a preferred embodiment of the invention, the gelling agent is added at a concentration of between 3 and about 5%, by weight. The co-surfactant is added at a concentration of between about 0.3 and about 0.5%, by weight. The acid is added at a concentration of between about 3% and about 28%, by weight. In a most preferred embodiment, the gelling agent is present in the fluid at a concentration of about 3-4%, the co-surfactant is present at a concentration of about 0.3-0.4%, and the acid is present at a concentration of about 25%.